1. Field of the Invention
Embodiments of the invention generally relate to hydrocarbon production, and more particularly, to drilling operations using well logging and measurement techniques for steering a drill bit within a pay zone in a lateral well using surface acoustic sensors generated by the drill bit drilling into rock.
2. Description of the Related Art
To increase oil or gas production of a well, an effective approach is to drill the well with a substantially lateral trajectory (e.g., a horizontal or lateral well) in a petroleum reservoir to increase the drainage area in the reservoir. It is therefore desired to maintain the drill bit within the targeted reservoir formation or pay zone during the horizontal or lateral drilling.
If the pay zone's geometry and distribution in space is precisely known, it will be easy to maintain the drill bit within the pay zone during lateral drilling. However, this is rarely the case. Geometry and distribution information of a pay zone before drilling, normally derived from seismic survey, offset wells, and local geological information, has significant error. Therefore, it can be extremely difficult to achieve good contact (i.e., high portion of a lateral section within a pay zone) if only the predefined geometry and distribution information of the pay zone is used to steer the drill bit through the pay zone in the lateral well, especially when the pay zone is thin.
To achieve better contact within the pay zone, geosteering can be employed. Traditionally, geosteering has been used to determine the position of the drill bit or drill string relative to the boundary between the pay zone and the surrounding rocks (e.g., overlying, underlying, and lateral layers) during drilling. The relative position of the drill bill is used to steer the drill bit within the pay zone, producing a lateral section having a maximum contact within the pay zone of the lateral well.
For example, measuring rock properties during drilling can provide the operator the ability to steer a drill bit in the direction of desired hydrocarbon concentrations. These types of systems typically utilize acoustic sensors located inside or adjacent to the drilling string to transmit acoustics associated with the drill bit encountering downhole rock formations (e.g., overlying, underlying, and lateral layers). Acoustic sensor data can be relayed to a measurement-while-drilling (MWD) or logging-while-drilling (LWD) tool, which either relays data via a wireline running inside the drilling string to the MWD/LWD tool at the surface, or through a borehole acoustic telemetry system which translates an acoustic signal through the drilling string or through the adjacent formation layers. Each methodology has its own set of disadvantages.
The wireline technique, although providing an arguably higher data rate, requires a wireline connected to the MWD/LWD tool, which must be deployed with the MWD/LWD tool. The acoustic telemetry methodology, albeit arguably the cheapest to implement, has a limited data rate, and thus, cannot support the transmission of raw data, requiring some form of lossy data reduction.
Many of the conventional MWD/LWD geosteering tools, some of which are configured to have a bit rate capability that can be sufficient to allow for the provision of raw data, only provide data describing encountered rock used in steering the drill bit that is behind the drill bit. For example, a measurement sensor of a conventional geosteering system is positioned a few dozen feet (e.g., 30 to 50 feet) behind the drill bit. Therefore, location of the boundary between the pay zone and the overlying rock (i.e., upper boundary), and the boundary between the pay zone and the underlying rock (i.e., lower boundary), are determined at the measurement sensor's position behind the drill bit. The drill bit is steered or maintained within the pay zone by keeping the drill string, at the sensor position, in the middle, or certain position between the upper and lower boundaries, of the pay zone. Because the measurement sensor is positioned behind the drill bit, conventional geosteering systems are unable to immediately notify an operator that the drill bit has already left the pay zone. Therefore, these tools are not true real-time tools.
In other conventional geosteering systems, drilling tools use either resistivity or sonic measurement to guide the drill bit during horizontal or lateral drilling. When resistivity measurements are employed, the upper and lower boundaries are computed from geological models using inversion techniques. A geological model can include predefined surrounding layers, predefined resistivity of the pay zone and the surrounding layers, and assumed thickness of the pay zone and the surrounding layers. In the inversion calculation, predicted tool response can be computed from a predefined geological model. The difference between the predicted tool response and the measured one can be calculated. If the difference is less than a preselected threshold, the assumed thicknesses of the pay zone and surrounding layers are treated as the “right” ones and the upper and lower boundaries are thus derived. Therefore, in this process, different combinations of layer thicknesses are searched until a right set is found. As rooted in the inversion techniques, the solution is not unique (i.e., different combinations of the thickness of pay zone and surrounding layers with different resistivity can result in the same or similar resistivity patterns). Thus, for the same measured resistivity pattern, different upper and lower boundaries can be determined.
When sonic measurements are employed, the upper and lower boundaries can be calculated from the travelling time of the reflected sonic waves and sonic velocity of the formation rocks. Sonic velocities of the formation rocks can be measured in-situ or determined prior to drilling.
Therefore, the aforementioned conventional geosteering systems are limited in that the formation used to steer the drill bit is derived at the location of the measurement sensor a few dozen feet behind the drill bit. Therefore, it is possible that although the position of the measurement sensor is in the pay zone, the drill bit may be drilling out of the pay zone. When it is determined that the drill bit is following the incorrect path at the measurement sensor location, a certain significant length of lateral section may have already been drilled out of the pay zone. When this happens, it may require a significant distance to adjust the drill bit back into the pay zone, resulting in a lateral section of the well with some non-productive fractions and thus reducing productivity of hydrocarbon production. As previously described, conventional geosteering systems are also limited by the use of resistivity techniques producing non-unique solutions, thereby reducing productivity of hydrocarbon production.
Some newer types of geosteering systems utilize a dedicated electronics unit and a segmented broadband cable protected by a reinforced steel cable positioned within the drill pipe to provide a faster communication capability. Such geosteering systems have been employed into conventional LWD tools to enhance the resolution of the logged information. However, the modified tools still measure rock properties 30-50 feet behind the drill. Furthermore, such geosteering systems require the provision of a segmented cable, whereby each segment connects to an inductive coil at the end of each separate drill pipe, which must survive the forces and environment encountered when connecting/running the drill pipe segments.
Other newer types of geosteering systems attempt to provide data for steering the drill bit, at least near-real-time, while still utilizing conventional borehole telemetry systems (i.e., having a relatively slow bit rate). These geosteering systems can include, for example, a downhole processor configured to provide downhole on-site processing of acoustic data to interpret the lithographic properties of the rock encountered by the drill bit through comparison of the acoustic energy generated by the drill bit during drilling with predetermined bit characteristics generated by rotating the drill bit in contact with a known rock type. The lithographic properties interpreted via the comparison are then transmitted to the surface via the conventional borehole telemetry system. Although providing data in a reduced form requiring only a bit rate speed, these conventional geosteering systems fail to provide raw data real-time which can be used for further analysis. It is nearly impossible to construct additional interpretation models or modify any interpretation models generated by this type of downhole processor. Further, they require additional and potentially expensive hardware that must be positioned between the drill bit and the drill.
Looking outside the field, some conventional seismic signal technology includes utilization of a vibration sensor positioned on a mud swivel to pick up the seismic signal generated by drill bit drilling the rocks. It is understood, however, that such a position does not provide for sufficient reception of the pilot signal. Another form of seismic signal technology provides a dedicated coupling connector encircling the drill pipe at a location near the mud swivel to carry vibration sensors. The strength of the seismic signal may be weakened due to its travelling through the connector to the vibration sensors. Besides requiring the addition of the coupling connector, which includes an annular stator/retaining ring enclosing an insulating rotor, such technology requires the signal to be transferred externally through a combination rotor-stator-brush wiper engagement methodology. Studies have demonstrated that signal accuracy is reduced by this transmission method. Both these two technologies are designed for rotary table type drill rigs which have almost been phased out by a new type of top drive drill rigs.
In order to improve the contact of the drill bit through the pay zone of the lateral well while drilling, and thus, the productivity of hydrocarbon production processes, apparatuses, computer program products, and methods are needed for steering the drill bit through the pay zone in real-time. More particularly, what is needed is (1) an apparatus specifically designed to fit top drive type drill rigs and having acoustic sensors strategically placed on the drill rig to maximally pick up the drilling sound which is generated by the drill bit biting the rocks (i.e., hereinafter referred to as “drilling acoustic signals”), (2) a signal transmitting system to transmit signals at high accuracy, and (3) a computer/processor positioned to receive acoustic signals from the acoustic sensors and configured to process the acoustic signals and evaluate the properties of the rock (e.g., lithology type and other petrophysical properties, as non-limiting examples) that is currently in contact with an operationally employed drilling bit, to utilize acoustic information contained within the acoustic signals and/or evaluated characteristics of the acoustic signals, and to generate instructions for steering the drill bit through the pay zone in real-time based on the derived rock type and properties. Also recognized is the need for methods of employing the apparatus.